Pertamina has completed the construction of the 67 km gas pipeline supplying gas to its Unit II Refinery in Dumai. With the commissioning of the 24-inch pipeline on 14 April 2019, the fuel needed to operate the refinery is now supplied by the gas produced from the nearby gas fields.
The gas comes from the following three blocks:
The prolific Grissik field located in the Corridor Block which is operated by ConocoPhillips. The Grissik field produced more than 900 MMSCF of gas per day in 2018. With an area of 2258 square kilometer, the Corridor Block is one of the largest gas blocks in Indonesia. Other very large gas blocks are the Tangguh and the Mahakam blocks.
The fields located in the Bentu Block which is managed by PT Mega Energi Persada (PT EMP). The Bentu Block is located near the city of Pekanbaru. PT EMP also supplies its gas to Indonesia’s state power company (PLN) and Riau Andalan Pulp and Paper (RAPP).
The oil and gas fields located in the Jambi Merang Block which is now operated by Pertamina Hulu Energi Jambi Merang (PHE Jambi Merang). PHE Jambi Merang acquired the block from the Joint Operating Body Pertamina-Talisman Jambi Merang on 9 February 2019.
In the past, the refinery used the fuel oil, Naptha and fuel gas it produced internally to meet the fuel needs of the refinery.
The project has brought significant economic benefits to both the gas producers and the refinery. In using the gas, the refinery is able to reduce its fuel costs by 40%.
The average crude oil production in Indonesia in 2018 is 803,000 barrels per day according to SKK Migas of Indonesia.
Here are the top ten crude oil producing companies in Indonesia in 2018.
Chevron Pacific Indonesia – 209,000 BOPD
Chevron is the biggest oil producer in Indonesia in 2018 and has been a leading oil producer in Indonesia for more than 90 years. It started operating in Indonesia in 1924 under Standard Oil Company of California.
Chevron operated oilfields in Sumatera and East Kalimantan. It’s East Kalimantan assets came from the acquisition of Unocal in 2005. Chevron handed back all the assets in East Kalimantan to Indonesia government on October 24, 2018, after 50 years of operation under Unocal and Chevron.
Currently, Chevron’s oil production comes mainly from the oil fields located in Riau, Sumatera under the Rokan Production Sharing Contract. The biggest oil field in the Rokan PSC is the Duri field which has been under steam-flood since 1985 and is one of the largest steam flood projects in the world.
ExxonMobil Cepu Ltd – 208,000 BOPD
ExxonMobil Cepu Ltd is the operator of the Cepu block located in Central Java and East Java. The Cepu Cooperation Contract (KKS) was signed on 17 September 2005 and will continue until 2035. ExxonMobil holds a 45% interest in the Cepu block.
ExxonMobil started exploration in 1999, and the oil from the Banyu Urip field started to flow in December 2008.
Pertamina EP – 79,000 BOPD
Pertamina EP operated 21 oil and gas fields located in various parts of Indonesia. These oilfields are managed under five asset groups based on their geographical locations.
Located in North Sumatera and some part of South Sumatera, the Asset One oilfields include Rantau Field, Pangkalan Susu Field, Lirik Field, Jambi Field, dan Ramba Field.
Located in South Sumatera, the Asset Two oilfields include Prabumulih Field, Pendopo Field, Limau Field dan Adera Field.
Located in West Jawa, the oilfields included in Asset Three are Subang Field, Jatibarang Field dan Tambun Field.
Located in Central and East Jawa, the Asset Four oilfields include Cepu Field, Poleng Field dan Matindok Field.
Located in Eastern part of Indonesia, the oilfields in Asset Five are Sangatta Field, Bunyu Field, Tanjung Field, Sangasanga Field, Tarakan Field dan Papua Field.
Pertamina Hulu Mahakam – 42,000 BOPD
Pertamina Hulu Mahakam became the operator of the oil and gas fields located in the Mahakam Block on 1 January 2018. The fields were previously discovered and operated by Total along with Inpex as its partner. They acquired the block in 1966.
Several giant oil and gas fields are located in this block such as the Handil field, the Tunu field, and the Peciko field.
Pertamina Hulu Energi OSES (Offshore South East Sumatera) – 30,000 BOPD
Pertamina Hulu Energi OSES became the operator of the oil fields in Block South East Sumatera on September 6, 2018. The fields were previously operated by CNOOC, China National Offshore Oil Company.
Pertamina Hulu Energi ONWJ – 29,000 BOPD
Pertamina Hulu Energi ONWJ (PHE ONWJ) is currently the operator of the Offshore North West Java (ONWJ) production sharing contract following the change of company ownership from BP to Pertamina in July 2009.
The contract area, located in the Java Sea, covers an area of approximately 8,300 square kilometers – stretching from the North of Cirebon to Kepulauan Seribu.
The giant Ardjuna field is located in this Production Sharing Contract area. It was discovered by ARCO – Atlantic Richfield Company – in 1969 and operated by ARCO until BP – British Petroleum – acquired ARCO in 2000.
The production facilities consist of 670 wells, 170 shallow water platforms, 40 processing and service facilities and some 1,600 kilometers of sub-sea pipeline.
Medco EP Natuna – 16,000 BOPD
Medco EP Natuna, a subsidiary of Medco Energi, is the operator of the South Natuna Sea Block B. The field was initially operated by ConocoPhillips until Medco Energi acquired it in 2016.
Besides producing oil, Medco EP Natuna also supplies gas to Singapore using a 656 KM long 28” subsea pipeline.
Petronas Carigali (Ketapang) – 15,000 BOPD
Petronas Carigali Ketapang operates the Bukit Tua Field located in the Ketapang Block in East Java. Bukit Tua is an oil field but with a significant amount of associated gas. The offshore field is situated at a water depth of about 57 m.
The production facilities consist of wellhead platforms, an FPSO – Floating Production, Storage and Offloading – and onshore receiving facilities (ORF) in Gresik.
PetroChina International Jabung – 14,000 BOPD
PetroChina International Jabung operates the prolific Jabung Block located in Jambi in Central Sumatera.
The company produces crude oil, condensate, LPG and gas. PetroChina supplies gas to Singapore using a 450 KM long subsea pipeline.
An interesting aspect about the block is that PetroChina discovered the fractured basement rock contains a significant quantity of gas can flow at significant rates.
Pertamina Hulu Kalimantan Timur – 13,000 BOPD
Pertamina Hulu Kalimantan Timur operates the East Kalimantan-Attaka Work Area. Chevron was the previous operator of the work area until it handed over the operatorship to Pertamina on October 25, 2018.
Attaka, the famous giant oil field is located in this block. The Attaka field was discovered and operated by Unocal until Chevron acquired it in 2005.
The oil fields in this work area are in the late declining phase. Around one billion barrels of oil and 3 TCF of gas have been produced from this work area.
Here are the key concepts and methodologies which a reservoir engineer should understand to simulate a reservoir effectively, according to Emeritus Professor Val Pinczewski of the University of New South Wales.
The internal structure of reservoir simulators – single, two and three phase reservoir simulators, black oil and modified black oil simulators, compositional simulators.
Limitations of numerical solution methods – truncation errors, numerical dispersion and stability, grid orientation effects.
Rock properties and saturation functions – design of effective SCAL programs and reservoir wettability, two and three-point saturation end-point scaling, rock-typing and hydraulic flow units, Leverett J-Function and Corey based models for relative permeability and capillary pressure, averaging saturation dependent property data, limitation of three-phase relative permeability and capillary pressure models.
Upscaling and relative permeability pseudo-functions – dynamic pseudo-functions, vertical equilibrium, and viscous dominated pseudo-functions.
Grid selection – advantages and disadvantages of structured, unstructured and hybrid gridding systems, corner-point geometry grids, PEBI grids, locally orthogonal grids, vertical heterogeneity and layering, guidelines for grid design.
Model initialization – Capillary-gravity equilibrium, initialization with zero capillary pressure, initialization using an average capillary pressure curve, initialization using the Leverett J-Function and a reference capillary pressure curve, initialization using Eclipse SWATINIT method. Effect of different options for run-time capillary pressure.
Aquifer modeling and history matching – unsteady-state water influx, Hurst and van Everdingen model, Carter-Tracy and Fetkovich models, material balance and aquifer history matching, guides for effective aquifer model history matching.
Well models and gas condensate reservoir modeling – condensate blockage and the two-phase pseudo-pressure method, implementation of the method in commercial reservoir simulators, gas condensate inflow relationships, PVT and fluid flow relationships for gas-oil relative permeability ratios, gas relative permeability ratio as a function of gas-oil relative permeability ratio, high velocity effects, positive and negative coupling, velocity dependent relative permeability and capillary number, guidelines for running gas condensate reservoir simulations using commercial reservoir simulators.
Val Pinczewski is Emeritus Professor in the School of Petroleum Engineering at the University of New South Wales. He established Australia’s first fully accredited degree program in Petroleum Engineering at the University of New South Wales in 1985. He conducts research in the areas of improved oil and gas recovery and in flow through porous media.
He was a founding member of the Australian Petroleum Cooperative Research Centre and managed its improved oil and gas recovery programs. In collaboration with colleagues at the Australian National University, he established a large interdisciplinary research group which is pioneering the use of high-resolution X-ray tomography to study the microstructure and transport properties of naturally occurring porous rocks of specific interest to the petroleum industry. The research was supported by a large consortium of the world’s leading petroleum companies and has produced a spin-out company based on this emerging technology.
He is a technical consultant to Westpac’s Institutional Bank where he assesses field development plans for major oil and gas developments throughout Australia and SE-Asia. He was involved in the development of NSW State Government industry guidelines for fracking and well integrity for Coal Seam Gas developments in the state.
Prior to joining the University of New South Wales, he worked for Esso Australia as a reservoir engineer both in Australia and abroad where he was responsible for conducting reservoir simulation studies and conducting and interpreting oil and gas well tests. He is an active consultant to industry in these areas.
He holds BE and Ph.D. degrees in Chemical Engineering from the University of New South Wales and is the author of numerous technical publications in the areas of improved oil and gas recovery, reservoir simulation and image-based core analysis.
The Sarulla power plant with a total capacity of 330 MW is the largest geothermal power plant in Indonesia and also one of the 10 largest geothermal power plants in the world.
The Sarulla power plant has three combined cycle units. Construction of the power plant started in May 2014 and the first unit named Silangkitang was completed in March 2017. Units Namora I-Langit 1 and Namora I-Langit 2 started operation in October 2017 and May 2018 respectively.
Located in North Sumatera of Indonesia, the power plant is operated by Sarulla Operations Ltd, a consortium consisting of Medco Energi, Itochu, Kyushu Electric Power Company, Inpex and Ormat with a total investment of US $1.7 billion.
The generated electricity is distributed by PLN, Perusahaan Listrik Negara, which is the state-owned electricity company of Indonesia.
This project demonstrates the commitment of the Indonesian government to increase energy production from renewable resources, especially from its huge geothermal potential. Indonesia has 40% of the world’s geothermal resources. The Indonesia government said three new geothermal power plants will start to operate this year. They are the 55 MW PLTP Lumut Balai, 40 MW PLTP Sorik Marapi and the 5 MW PLTP Sokoria.
The total installed geothermal power in the world in 2018 is 14,600 MW according to ThinkGeoEnergy. The five countries producing more than one Giga Watt (GW) of geothermal power are:
The USA – 3639 MW
Indonesia – 1948 MW
The Philippines – 1868 MW
Turkey – 1347 MW
New Zealand – 1005 MW
Here is a little bit of interesting history about the Sarulla project. The Sarulla geothermal resource was originally explored and discovered by Unocal North Sumatera Geothermal. Unocal’s plan to construct the first power plant was suspended during the financial crisis in 1998.
According to EIA, the US Energy Information Agency, the top ten countries with the largest amount of proven oil reserves in 2017 are:
Venezuela – 300 billion barrels
Saudi Arabia – 266 billion barrels
Canada – 170 billion barrels
Iran – 158 billion barrels
Iraq – 142 billion barrels
Kuwait – 101 billion barrels
UAE – 98 billion barrels
Russia – 80 billion barrels
Libya – 48 billion barrels
Nigeria – 37 billion barrels
The United States, currently the largest oil producer in the world, is ranked at number eleven with proven oil reserves of 35 billion barrels of oil. Most of the increases in oil production in the US come from the production of shale oil. The US is the world leader in oil shale drilling.
It is interesting that although Venezuela has the most oil in the ground, it is no longer one of the top ten oil producers in the world.
In 2018, daily world oil production amounts to around 92 million barrels per day, increasing slightly 0.7% from previous year.
Here are the world top ten oil producers according to the US Energy Information Administration (EIA) in 2017:
USA – 15.6 Million barrels of oil per day
Saudi Arabia – 12.1 Million BOPD
Russia – 11.2 Million BOPD
Canada – 5.0 Million BOPD
China – 4.8 Million BOPD
Iran – 4.7 Million BOPD
Iraq – 4.5 Million BOPD
UAE – 3.7 Million BOPD
Brazil – 3.4 Million BOPD
Kuwait – 2.9 Million BOPD
The USA is the largest oil producer in the world in 2017. The production of crude oil in the USA is expected to increase into 2019. The USA is also the world’s largest consumer of oil. Its daily oil consumption in 2019 is projected to increase by 340,000 barrels to 20.65 million barrels, according to EIA.
EIA reported on 21 December 2018 United States produced a total of 16.3 million barrels per day of crude oil and natural gas liquids in November 2018. This total production consists of 11.7 million BPD of crude oil and 4.6 BPD of natural gas liquids or NGL.
Saudi Arabia, on the other hand, is the largest oil exporting country. As the most well-known and influential oil producer, it has 260 billion barrels of oil reserves, which is about 22% of the world’s oil reserves.
Unconventional oil and gas resources are resources where the oil and gas are difficult to recover or produce due to either the very low permeability of the formation or the very low mobility of the hydrocarbons. Special techniques and processes are required to recover these types of resources.
The three common types of unconventional hydrocarbon resources are:
Shale oil and shale gas.
The world’s largest oil sand deposit is the Athabasca oil sands located in Alberta, Canada. Oil sands are a mixture of semi-solid bitumen or asphalt and sand, and they are buried not far from the earth surface. Commercial production of the Athabasca oil sands began in 1967 and the current production is at around two million BOPD. Many major oil companies are involved in the production of these oil sands.
Two methods are used to recover the oil from the oil sands. They are open-pit mining and the SAGD method.
Open-pit mining method is commonly used to extract the oil from oil sands located near the earth surface. After the tar sand is mined, it is mixed with hot water and agitated to form a slurry. The released bitumen droplets will float to the surface with the help of the tiny air bubbles which attach to the bitumen droplets. The bitumen will then be skimmed off and further processed to remove the remaining water and solids. Lastly, the bitumen will be upgraded to synthetic crude oil. About 75% of the bitumen can be extracted from the tar sands.
For tar sands located at a deeper depth, in-situ production methods are used, such as steam injection, fire flooding, and chemical injection. A popular steam injection method is the SAGD method. In SAGD, steam-assisted gravity drainage, a pair of horizontal wells are drilled into the oil sand, one at the bottom of the formation and another about 5 meters above it. High-pressure steam is injected into the sand from the upper well to heat the heavy oil and thus reduce its viscosity. With the increase in mobility, the oil drains into the lower well where it is pumped to the surface. SAGD is the preferred method for extracting the oil sands due to environmental concerns.
Shale Oil and Shale Gas
Another currently popular unconventional hydrocarbon resource is shale oil and shale gas. Shale oil is oil that is trapped inside the tight shale. Shale is a hard sedimentary rock
composed of clay that is rich in organic materials. Since tight shale has very low permeability, hydraulic fracturing method is used to extract the oil. In hydraulic fracturing, a large quantity of viscous fluid carrying sand is pumped into the well under high pressure to fracture the shale, creating pathways and highways for the oil to flow out of the shale and into the wellbore.
Most shale oil production takes place in the US and the daily production of shale oil reaches six million BOPD in 2017. A large quantity of gas is also produced from shale. According to the US Energy Information Agency (EIA), gas production from shale in the US in 2016 was 15.8 trillion cubic feet (TCF).
The most well-known and top shale oil plays in the US are The Permian Basin and Eagle Ford Shale in Texas, and Bakken Shale in North Dakota.
Coal Bed Methane
Coalbed methane (CBM) is an unconventional resource of methane gas. It is being produced successfully in some parts of the world, notably in Australia and Canada. Since coal is formed from organic materials, methane gas (CH4) is generated during the formation of coal. The generated methane is adsorbed in the coal matrix, fractures and coal seams called cleats. Cleats are horizontal and vertical fractures formed naturally in coal.
Wells are needed to produce the trapped methane gas. Since underground coal is usually saturated with water, methane is extracted by first removing the water from the coal by pumping out the water. As the water is pumped out from the well, the coal pore pressure will decrease causing the adsorbed gas to be liberated from the coal and then flow to the wellbore. Due to the low permeability of the coal matrix, the coal must have a sufficient network of fractures and cleats to produce the methane gas at economic production rates.
Since 1966 when Indonesia began offering production sharing contracts (PSC) for international companies to explore and produce oil and gas in Indonesia, many giant and super-giant oil and gas fields were discovered.
Giant fields are those with estimated ultimate recoverable reserves (EUR) of 500 million barrels of oil or gas equivalent (MMBOE) and super giant oil fields are those holding an equivalent of 5.5 billion barrels of oil reserves.
Here are the ten giant offshore oil and gas fields in Indonesia discovered between 1966 and 2000.
1. Abadi Field
Abadi is a giant gas field discovered by Inpex in 2000 in the Masela contract area in the Arafura Sea. The Abadi field has an estimated ultimate recovery (EUR) of 768 MMBOE and it is located 93 miles offshore from the province of Maluku in the eastern part of Indonesia.
Originally the field would be developed using subsea production system and a floating LNG (FLNG) facility. The plan now is to develop the field based on an onshore LNG development concept.
Inpex in partnership with Royal Dutch Shell is currently conducting preliminary front-end engineering design (Pre-FEED) studies for the Abadi field development based on an onshore concept. The LNG project will produce 9.5 MM tons of LNG annually.
When developed, the Abadi field may become the biggest deepwater gas project in Indonesia. It is expected to produce more than 1 billion SCF of gas per day and 20,000 barrels of condensate per day for 24 years.
2. Gula Field
The Gula field is an offshore gas field discovered by Unocal in its Ganal production sharing contract area located in the Kalimantan strait in 2000. With an EUR of 545 MMBOE, it is a giant gas field.
The Gula field, along with the Gendalo discovery and the Gada discovery, is one of the many discoveries made by Unocal in the deep-water area between Kalimantan and Sulawesi. These discoveries confirm that the Central Delta play contains world-class gas resources.
The Gula field is currently an undeveloped discovered resource.
3. Ubadari Field
Ubadari is a giant offshore gas field discovered in 1997. The Ubadari field has an EUR of 500 MMBOE and it is located at Bintuni Bay in West Irian province.
The Ubadari field will supply its gas to Tangguh LNG plant when the Tangguh LNG Train-3 project is completed in 2020. The Tangguh expansion aims at meeting the ever-increasing demand for energy in Indonesia and accelerating the development of West Irian.
PLN, Indonesia’s electricity company, has signed a sales and purchase agreement to buy up to 1.5 million tons of LNG produced by Tangguh LNG plant annually.
Tangguh LNG plant is scheduled to process the gas produced from the six gas fields located at Bintuni Bay: Vorwata, Wiriagar Deep, Ofaweri, Roabiba, Ubadari, and Wos.
4. Vorwata Field
Vorwata is an offshore giant gas field located in Bintuni Bay in West Irian Province. The Vorwata field, with EUR of 1833 MMBOE, was discovered by ARCO in the Berau block in 1997. BP became the operator of Vorwata field after it acquired ARCO.
Gas production from Vorwata field started in 2009. The field is capable of producing more than 1 BCF of gas per day and the gas is processed into LNG by the Tangguh LNG plant.
5. West Seno Field
The West Seno field is a deepwater oil field discovered by Unocal in 1996. Having an EUR of 553 MMBOE, it is a giant oil field and is currently operated by Chevron.
Lying in water depths of 2,400 to 3,400 feet, the West Seno field is Indonesia’s first deepwater development. It lies in the Makassar Strait PSC off Kalimantan on the continental slope of the northern Mahakam Delta.
The oil is produced using two tension leg platforms and a floating production unit, tied back by two export pipelines to onshore infrastructure.
6. Peciko Field
Peciko is a gas field located offshore in the Mahakam Delta in East Kalimantan. The field was discovered by Total with INPEX as its partner in 1991. The Peciko is a giant gas field having EUR of 1180 MMBOE.
Of all the producing fields in the Mahakam River delta, the Peciko field is unique in that its reservoir trap is both structural and stratigraphic.
The Peciko wells are highly productive having an average well productivity of 80 MMSCF of gas per day. Total daily gas production exceeded 1 BSCF during its peak. A substantial quantity of condensate is being produced along with the gas.
7. Tunu Field
The Tunu field is a supergiant gas field discovered by Total along with Inpex as its partner in 1977. It is located at the shallow waters along the outer limits of the delta offshore Mahakam Block in East Kalimantan. It has an EUR of 4378 MMBOE.
Started in 1978, the Tunu field produces gas and condensate having negligible CO2 or H2S, with the main productive reservoirs lying at depths from 2,200 to 4,900 meters.
Developing the large Tunu field is challenging and producing the gas requires drilling a large number of wells. The field has a large surface area of 20 Km wide and 75 Km long and it is located at the wetland of Mahakam swamp.
8. East Natuna Field
The offshore East Natuna gas field was discovered by AGIP in 1970. It is located 140 miles northeast of the Natuna Islands, Indonesia’s northernmost territory. It is a super-giant gas field with estimated recoverable reserves of 46 trillion cubic feet (TCF) of gas.
There were serious studies done and attempts made by Exxon-Mobil and Pertamina to develop this field.
The field is currently undeveloped due to its very high CO2 content of 71%. To produce the gas will require removing the CO2 from the gas and injecting it back into the reservoir. Production can be commercially viable when the price of oil is above $100 per barrel.
9. Attaka Field
The Attaka field is a giant oil and gas field discovered by Unocal in partnership with Inpex in 1970. Chevron became the field operator after it acquired Unocal in 2005. Having an EUR of 1000 MMBOE, the Attaka field is located 12 miles from the shore of East Kalimantan.
The huge Attaka reservoir, formed in the very prolific Kutei basin, has an areal closure of 8000 acres. Due to its large areal extent, originally the oil and gas were produced from more than 100 wells located in 6 remote wellhead platforms.
Ten years later, five subsea wells were completed in 1981-1984 to produce the untapped oil accumulation in areas out of reach of the existing remote platforms. These are the first subsea completions in Indonesia.
Attaka field daily oil production was 110,000 BOPD at its peak and gas production was 150 MMSCFPD. Now the Attaka field is quite depleted.
10. Ardjuna Field
The Ardjuna Field is a giant oil field having an EUR of 698 MMBOE. This is the first offshore giant field discovered since the birth of the Indonesian PSC system in 1966.
The Ardjuna field was discovered by ARCO in the Offshore North West Java (ONWJ) production sharing contract area in 1969. Subsequently, it was operated by BP when it acquired ARCO in 2000. Now the field is operated by Pertamina Hulu Energy ONWJ Ltd.
Interesting facts about the Ardjuna field include the drilling of the first horizontal well in Indonesia in 1985 and supplying gas to PLN’s power plant in Muara Karang in Jakarta in 1993.
Pertamina’s refinery in Cilacap began using crude oil from Ardjuna field in 1986.
The traditional oil we use to lubricate our car engine is called mineral oil because it is derived from crude oil. Mineral oil consists of hydrocarbon molecules extracted from the distillation of crude oil. They are mainly alkanes in the range of C-15 to C- 40.
An alkane is a saturated hydrocarbon consisting of only carbon and hydrogen atoms. Also called paraffin, it has the general formula of CnH2n+2. The simplest alkane is methane, CH4, where the n=1.
Due to the chemical and physical properties of the hydrocarbon alkanes, they have limited resistance to oxidation and thermal breakdown at very high temperature.
Synthetic oil, on the other hand, consists of synthetic molecules. They are artificially made and specially designed to provide excellent lubrication and stability at very high and also at low temperature. Since these synthetic molecules do not deteriorate easily, they can last longer than mineral oil even at extreme conditions in an engine.
Synthetic oil is more expensive than mineral oil, nevertheless, it is a superior lubricant to keep your car healthy. With mineral oil, it is recommended you change the oil every 5000 to 10,000 miles. Whereas using synthetic oil, you may change the oil every 20,000 miles.
Finally, it is important to note regardless of the type of oil you use, you should change your engine oil based on the recommended interval because it gets contaminated with combustion by-products that accumulate at about the same rate regardless of oil type.